Methods and materials for evaluating and improving the production of geo-specific shale reservoirs

ABSTRACT

Diagnostic or assisting lateral wellbores can have a significant benefit for injecting and distributing treatment fluids and other materials within complex fracture networks that surpass conventional injection at the primary lateral wellbore perforations for acquiring empirical knowledge about the numerous processes that influence shale reservoir production which occur after primary shale reservoir stimulation. Injection of diagnostic treatment fluids or treating chemicals for understanding production optimization, such as water-block removal, fines migration removal, and treating chemicals for prevention of scale and paraffin deposition, can be injected along the diagnostic lateral wellbore or frac interval lateral wellbores to give broader and/or deeper distribution into the fracture network than by using mono-bore-centric diagnostic injection techniques. Diagnostic lateral treatment techniques can also improve fluid or chemical distribution, such as the use of gas injection to help energize fluid flow to the primary lateral during production optimization treatments, including reverse diversion methodology.

TECHNICAL FIELD

The present invention relates to methods of obtaining information about subterranean formations and features therein using multiple wellbores, and more particularly relates, in one non-limiting embodiment, to methods of obtaining information about and treating unconventional shale subterranean formations and features thereof using multiple wellbores comprising at least one primary lateral wellbore and at least one diagnostic lateral wellbore adjacent thereto.

TECHNICAL BACKGROUND

It is well known that hydrocarbons (e.g. crude oil and natural gas) are recovered from subterranean formations by drilling a wellbore into the subterranean reservoirs where the hydrocarbons reside, and using the natural pressure of the hydrocarbon or other lift mechanism such as pumping, gas lift, electric submersible pumps (ESP) or another mechanism or principle to produce the hydrocarbons from the reservoir. Conventionally most hydrocarbon production is accomplished using a single wellbore. However, techniques have been developed using multiple wellbores, such as the secondary recovery technique of water flooding, where water is injected into the reservoir through one wellbore to displace oil out through another wellbore. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Potential problems associated with water flooding techniques include inefficient recovery due to variable permeability or similar conditions affecting fluid transport within the reservoir. Early breakthrough of the water through the oil is a phenomenon that may cause production and surface processing problems.

Hydraulic fracturing is the fracturing of subterranean rock by a pressurized liquid, which is typically water mixed with a proppant (often sand) and chemicals. The fracturing fluid is injected at high pressure into a wellbore to create, in shale for example, a network of fractures in the deep rock formations to allow hydrocarbons to migrate to the well. When the hydraulic pressure is removed from the well, the proppants, e.g. sand, aluminum oxide, etc., hold open the fractures once fracture closure is permitted or occurs. In one non-limiting embodiment chemicals are added to increase the fluid flow and reduce friction to give “slickwater” which may be used as a lower-friction-pressure placement fluid. Alternatively in different non-restricting versions, the viscosity of the fracturing fluid is increased by the addition of polymers, such as crosslinked or uncrosslinked polysaccharides (e.g. guar gum) and/or by the addition of viscoelastic surfactants (VES).

Recently the combination of directional drilling and hydraulic fracturing has made it economically possible to produce oil and gas from new and previously unexploited ultra-low permeability hydrocarbon bearing lithologies (such as shale) by placing the wellbore laterally so that more of the wellbore, and the series of hydraulic fracturing networks extending therefrom, is present in the production zone permitting more production of hydrocarbons as compared with a vertically oriented well that occupies a relatively small amount of the production zone. “Laterally” is defined herein as a deviated wellbore away from a more conventional vertical wellbore by directional drilling so that the wellbore can follow the oil-bearing strata that are oriented in a non-vertical plane or configuration. In one non-limiting embodiment, a lateral wellbore is any non-vertical wellbore. In another non-limiting embodiment, a lateral wellbore is defined as any wellbore that is at an inclination angle from vertical ranging from about 45° to about 135°. It will be understood that all wellbores begin with a vertically directed hole into the earth, which is then deviated from vertical by directional drilling such as by using whipstocks, downhole motors and the like. A wellbore that begins vertically and then is diverted into a generally horizontal direction may be said to have a “heel” at the curve or turn where the wellbore changes direction and a “toe” where the wellbore terminates at the end of the lateral or deviated wellbore portion. The “sweet-spot” of the hydrocarbon bearing reservoir is an informal term for a desirable target location or area within an unconventional reservoir or play that represents the best production or potential production. The combination of directional drilling and hydraulic fracturing has led to the so-called “fracking boom” of rapidly expanding oil and gas extraction in the US beginning in about 2003.

Improvements are always needed in the driller's ability to find and map sweet-spots to enable wellbores to be placed in the most productive areas of the reservoirs. Sweet-spots in shale reservoirs may be defined by the source rock richness or thickness, by natural fractures present therein or by other factors. Conventionally, geological data, e.g. core analysis, well log data, seismic data and combinations of these are used to identify sweet-spots in unconventional plays.

Improvements are also needed in the amount of and quality of knowledge about fracture networks, the parameters that control fracture geometry and reservoir production, horizontal wellbores, fracture networks, and reservoirs may be treated to optimize hydrocarbon recovery, and the like.

SUMMARY

There is provided in one non-limiting embodiment a method for learning how to improve, through methodical, procedural, and empirical investigative techniques, the flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume having at least one assisting lateral wellbore substantially adjacent to and substantially parallel to the primary lateral wellbore, where the method includes hydraulically fracturing at least one first shale interval in the subsurface shale volume from the at least one primary lateral wellbore in the direction of the at least one assisting lateral wellbore to create at least a first fracture network, where the first fracture network is in fluid communication with the at least one assisting lateral wellbore. Alternatively, the method may utilize at least one primary lateral wellbore that has at least one fracture network along the lateral length of the primary later wellbore. The method additionally includes one or more sub-methods of (1) ultra-high resolution imaging utilizing moderately-close to ultra-close proximity imaging instruments and processes for determining reservoir production flow within the fractured network to the primary lateral wellbore; (2) introducing at least one diagnostic agent into the at least one lateral wellbore through the fracture network and the at least one assisting lateral wellbore, (3) introducing at least one treatment fluid into the at least one lateral wellbore and the fracture network for treating the at least one lateral wellbore and/or the fracture network with the treatment fluid, and/or (4) imaging flow and changes of flow within the fracture network. Further, the method may include producing the hydrocarbons from at least one of the lateral wellbores.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic, plan view of a series of shale intervals in a subsurface volume along two primary lateral wellbores and an assisting or diagnostic lateral wellbore, where complex fracture networks are schematically illustrated as extending from the primary lateral wellbores away from the primary lateral wellbores and also in the direction of the assisting or diagnostic lateral wellbore for placement of diagnostic agents, such as tracers;

FIG. 2 is a schematic, horizontal cross section of a subsurface shale volume showing two primary lateral wellbores and an imaging or diagnostic lateral wellbore, where upper and lower imaging lateral diagnostic wellbores are shown, as viewed from line 2-2 in FIG. 1; and

FIG. 3 is a schematic, three-quarters view illustrating two vertical wellbores directionally drilled to respective primary lateral wellbores extending therefrom and a third vertical wellbore directionally drilled to provide an assisting lateral wellbore that has upper and lower diagnostic lateral wellbores extending therefrom over and under the primary lateral wellbores.

It will be appreciated that the drawings are schematic and should be understood as not necessarily to scale or proportion, and that certain features are exaggerated for emphasis. Furthermore, the methods and configurations described herein should not be limited to particular embodiments illustrated in the drawings.

DETAILED DESCRIPTION

Obtaining hydrocarbon fluids from subterranean formations using a single wellbore or “mono-bore” approach, even implementing directional drilling and hydraulic fracturing, has a number of limitations, including, but not necessarily limited to, the primary method for obtaining information about the immediate environment of the single wellbore.

It has been discovered that the use of at least one diagnostic lateral wellbore adjacent or proximate to at least one primary lateral wellbore or another diagnostic lateral wellbore may provide a wealth of information, that is, empirical knowledge (defined herein as data) about the at least one primary lateral wellbore and/or diagnostic lateral wellbore and/or the subsurface volume surrounding these wellbores. As defined herein, in one non-limiting embodiment, assisting or diagnostic wellbores are lateral wellbores drilled for performing diagnostic-based treatments within one or more fracturing interval locations along the length of the lateral, for understanding and improving how best to diagnose, stimulate, treat, produce and even refracture geo-specific shale reservoirs, and may include eventual production of hydrocarbons from the reservoir into which they are placed for many types of treatments and/or treatment conditions and how best to influence reservoir hydrocarbon production.

As also defined herein, in one non-limiting embodiment, “near-wellbore” is within 10 to 20 feet (3 to 6 m) of the wellbore, alternatively within 40 to 60 feet (12 to 18 m) of the wellbore. In one non-limiting embodiment, “far-field” is defined as greater than 60 feet (18 m) from the wellbore; alternatively as 100 feet (30 m) or greater from the wellbore.

A further limitation with conventional mono-bore approaches is that after a fracturing treatment of shale formation in a subsurface volume bearing a hydrocarbon reservoir it is difficult to know what actually happened within the reservoir. There are and can be a large number of and variety of different types of complex fracture networks. It will be appreciated that each complex fracture network is different from the next, even comparing adjacent fracture intervals.

By “fracture networks” or “complex fracture networks” is meant that a series and/or distribution of multiple fractures are generated hydraulically that provide fluid flow pathways and communication through the ultra-low permeability shale reservoir to the wellbore or wellbores, in contrast to simply forming a single fracture and/or a few fractures within the shale reservoir that connect to the wellbore. It is much more desirable to create fracture complexity both in the near-wellbore region and far-field regions than to have a single fracture or a few large fractures. The more surface area of the shale reservoir that is exposed and connected to a wellbore or wellbores (i.e. complex fracture network) through hydraulic fracturing the better, that is, close to the wellbore (near wellbore complex fractures) as well as far from the wellbore (far-field complex fractures). In most cases, when hydraulically fracturing, far-field complex fracture networks are more difficult to create, and as compared to near wellbore complex fracture, typically have reduced number of fractures, surface area, and less flow path systems in further relation to the wellbore.

Additionally, different geo-specific shales react to the same fracture treatment in different ways. Furthermore, the methods described herein will help diagnose, analyze and interpret these complex fracture networks as they produce, as well as to obtain more accurate information about other subsurface volume structures, including the wellbore wall and earth and rock around the wellbore, as well as propped and unpropped fracture conductivity over time in regions of the fractured network system, and the like. Parameters that can be determined using one or more of the methods described herein include, but are not necessarily limited to, parameters that control reservoir fractured network production over time for geo-specific shales. These methods may also be used for quicker location of sweet-spot horizons in reservoirs (defined herein as the strata within a shale interval that represents the best production or potential production of hydrocarbons) and how produced reservoirs react to refracturing (refrac) techniques. “Refracturing” is defined herein as an operation to restimulate a well after an initial period of production where the well was previously fractured. Refracturing attempts to bypass or avoid near-wellbore damage and reestablish good connectivity with the reservoir, and/or also connecting with reservoir portions having higher permeability and pore pressure. Refracturing operations are also performed after a period of hydrocarbon production that can alter the stresses in a reservoir due to depletion, and the restimulation can allow new fractures to reorient in a different direction. In other words, accuracy in targeting and fracturing sweet-spot horizons may be improved through the methods and structures defined herein.

It has been discovered that many of these problems and limitations may be overcome using multiple lateral wellbores—beyond conventional “mono-bore” approaches. The use of multiple lateral wellbores can provide knowledge about processes including, but not necessarily limited to, fracture network closure, fracture network cleanup, optimized production enhancement and/or remediation treatments and other well treatments, multi-lateral refracturing (“refrac”) treatments, and combinations of these.

The method includes combinations of one or more diagnostic lateral wellbores adjacent and/or proximate to one or more primary lateral wellbores for fracture imaging and other data collection during and after diagnostic treatments and other well treatments. The method can, through optimized, close proximity to ultra-close proximity of diagnostic instruments to the fractured interval (i.e. solely for improving imaging resolution of stimulated interval) image shale complex fracture networks in real-time; that is during the different stages of hydraulic fracture treatment to a rock volume. By placement of these one or more diagnostic lateral wellbores in close proximity to ultra-close proximity for high to ultra-high imaging resolution of the fracture interval, these methods help observe and thereby learn and understand how treatment parameters control complex fracture network growth and geometry in geo-specific shales. As defined herein, moderately-close proximity is defined as between about 300 to less than about 600 feet (about 91 meters to less than about 183 meters) from the primary lateral, close proximity is defined as between about 200 feet to less than about 300 feet (about 61 to less than about 91 meters) from the primary lateral, very-close proximity is defined as between about 100 and less than about 200 feet (about 30 to less than about 61 meters) from the primary lateral, and ultra-close proximity is defined as between 0 feet to less than about 100 feet (0 to less than about 30 meters) from the primary hydraulic fracture and/or fracture plane generated during a primary diagnostic treatment. Ultra-high resolution is defined herein in relation to acoustic-based signal methodology, in one non-limiting embodiment, as the practice of signal transmission between primary lateral wellbores and diagnostic lateral wellbores; that is, the observable travel time difference of the acoustic signals passing through the lithology of the reservoir before hydraulic fracturing, changes to the reservoir during hydraulic fracturing, changes to the reservoir after the hydraulic fracturing, during reservoir hydrocarbon production, during diagnostic treatments and other fluid travel processes performed to the reservoir. The level of detail in reservoir changes for ultra-high resolution may include, but is not necessarily limited to: when micro-fractures initiate and as they grow wider apart; as hydraulic pressure expands the width of natural and/or hydraulically induced fractures in the shale between diagnostic instruments (such as an array of diagnostic lateral sensors picking up acoustic waves from acoustic generators arrayed in the primary lateral); when hydraulically induced fractures close (lose aqueous and/or gas fluid in fracture and fracture gap is geo-mechanically compressed) without proppant and with proppant in said fractures (i.e. speed change of acoustic wave travel geometric and time-related observations in relation to size and quantity of proppant placed in reservoir, etc.); differences observed in multiple real-time acoustic signal paths between the generator-sensor arrangements, arranged to observe acoustic speed reduction differences spatially in the reservoir and thus “hydraulic fractures generation” and “development of fracture network” real-time development; and reverse spatial signal speed change during “fracture network” closure or multiple fractures over time (change in signal speed rate decline until a faster more constant acoustic wave speed is obtained (i.e. closure of fractures), in which geometric regions of the fracture network may “close faster” than other regions by observing the rate for signal speed change followed by stability of acoustic wave speed spatial differences; where the distance between acoustic generators are between about 5 (about 1.5 m) independently to about 50 feet (about 15.2 m); or alternatively between about 10 (about 3 m) independently to about 40 feet (12.2 m); and again between about 15 (about 4.6 m) independently to about 30 feet (about 9.1 m) apart and can have sequences in pulsations along the generator array, where each acoustic generator can vary in signal time/duration, the signal intensity or magnitude generated (such as very intense acoustic signal magnitude for a period of one second in orchestrated pulsed sequence along the acoustic generator array where one generator at a time generates a signal followed by a methodical order of the generators composing the array, such as in series along the array of acoustic generators), and the like; where the acoustic sensors, in another non-limiting example, are between about 4 independently to about 40 feet (about 1.2 to about 12.2 m); or between about 5 independently to about 30 feet (about 1.5 to about 9.1 m); and again between about 6 independently to about 20 feet (about 1.8 to about 6.1 m); where the spatial area between acoustic generators and sensors is equivalent to distances listed for between primary lateral and diagnostic laterals, such as moderately-close proximity, close proximity, very close proximity and the like; where the type of data generated is directly related to the proximity of the primary and diagnostic laterals along with the number of and distance of the acoustic wave generators to the number of and distance of the acoustic wave sensors correlated with signal duration, signal intensity, timing or sequencing of signal transmission along the array of generators, and other acoustic wave pulsation methodologies for acoustic wave transmission through the reservoir; and combinations thereof. Acoustic signal speed changes can be correlated to treatment processes, volumes, fluid properties, and the like (i.e. diagnostic treatment parameters and spatial changes to the reservoir as observed by signal speed changes related to multiple signal paths angulations, etc.). In another embodiment, electromagnetic wave generators and sensors, also in array form, can be used similarly to the acoustic wave transmission and sensor collection embodiment. Generators can produce electromagnetic signals and electromagnetic sensors can collect signals, which like acoustic wave signals can provide data as listed above. The use of diagnostic laterals and their proximity placements herein is to obtain the highest imaging resolution possible for gathering as much information about physical changes to the immediate reservoir rock volume, during diagnostic hydraulic fracturing processes, during cleanup of the treatment fluid, during diagnostic well induced cleanup of the fracture network and/or interval (i.e. assisted cleanup to understand the importance of degree of treatment fluid cleanup to production), information about fracture network closure processes, during production optimization treatments originating from the primary and/or diagnostic lateral, and/or parameters that improve fracture network growth and treatment fluid recovery for refrac treatments.

More specifically, the use of diagnostic lateral wellbores can improve fracture imaging and diagnostic treatments. Fracture imaging includes, but is not limited to, imaging hydraulic fracture generation, mapping fracture network cleanup, production fluid mapping, imaging fractures during refracs, and wildcat field development data, fluid flow and hydrocarbon production before, during and after one or more well treatments, and the like. Diagnostic treatments include, but are not necessarily limited to, diagnostic frac treatments, diagnostic closure experiments, improving fracture network cleanup, optimizing production treatments, and diagnostic refrac treatments. Diagnostic information that may be generated includes, but is not necessarily limited to, parameters that control fracture geometry in geo-specific shales, parameters that control reservoir production for geo-specific shales, parameters for quicker location of sweet-spot horizons in reservoirs, parameters and materials and chemical processes for more effective treatment fluid recovery and resultant fracture network permeability and/or conductivity, and/or determining how produced reservoirs react to refracturing techniques.

In new field evaluations, the use of multiple diagnostic lateral wellbores can assist in locating economical horizons. In early field learning, these multiple diagnostic lateral wellbores can help in identifying and landing in sweet-spot horizons; help determine the primary lateral wellbore location and length, help determine diagnostic lateral wellbore type, placement and purposes; map fracture treatments (fracture network complexity as a function of design parameters); help design the number of fracture intervals, improve the basic frac treatment design, investigate aggressive frac and refrac processes, and improve fracture network cleanup and treatment cleanup techniques. In main field completions, the use of multiple lateral diagnostic wellbores can assist in optimizing frac treatments and cleanup designs. In mid- to late well production, multiple lateral wellbores can help with production fluid mapping, evaluation of production optimization treatments and the applications of treating chemicals. In refracs, the multiple lateral wellbores may assist with the selection of candidate fields, fracture intervals, the fracture treatment design and mapping, and fracture cleanup techniques. The use of one or more diagnostic lateral wellbores can help optimize fracturing treatment design for geo-specific shale reservoirs, that is, shale formations at a geographically specific location, as well as refrac designs. It is important for the shale completion industry to learn more specifically and much more quickly how each shale reservoir should be hydraulically fractured or refractured for optimum fracture complexity, surface area generated, amount and distribution of fracture conductivity, determination of high permeability and/or hydrocarbon sweet-spot horizons and the like. It is also important to the industry to know which well treatments are productive for which complex fracture networks so that only productive well treatments are employed.

Learning and diagnosing shale hydraulic fracturing includes at least seven areas: (1) fracture geometry, (2) fracture diversion and fracture complexity, (3) fracture conductivity, (4) fracture closure, (5) fracture cleanup, (6) dual-wellbore and multi-wellbore improvements (going beyond mono-bore stimulation and production), and (7) sweet-spots (the parameters controlling access to and stimulation of sweet-spot horizons). Fracture geometry includes, but is not necessarily limited to (a) effects of fluid parameters, (b) effects of treatment parameters, (c) effects of reservoir parameters, and (d) how to detect sweet-spot horizons. Fracture diversion and fracture complexity includes, but is not necessarily limited to (a) how to control fractures in specific locations, (b) effects of various treatment fluids, (c) effects of materials, concentrations, and staging, (d) effects of pump rate, and (e) effects of reservoir parameters. Fracture conductivity includes, but is not necessarily limited to (a) proppant transport and distribution, (b) complex fracture network conductivity, (c) primary fracture plane conductivity, and (d) transitional conductivity versus choke points. Fracture closure includes, but is not necessarily limited to (a) primary fractures, (b) complex fracture networks, (c) effects on fracture conductivity, and (d) optimum location(s) for inducing closure. Fracture cleanup includes, but is not necessarily limited to (a) effects of natural cleanup methods, (b) effects of induced cleanup methods, (c) importance of complex fracture network cleanup, (d) importance of primary fracture network cleanup, (e) importance of distance and conductivity to perforations, and (f) effects on sweet-spot productivity.

In another non-limiting embodiment, the process of establishing communication between adjacent lateral production wellbores, for improving methods to induce fracture network closure, for cleaning up fracture networks, injecting production chemicals and performing well treatments, performing refracs, as well as the time between drilling primary laterals and assisting laterals can be several years, and after primary laterals or other lateral wellbores have been produced for several years. In other words, acreage and a field of lateral production wellbores may already exist where in-field drilling of additional lateral wellbores between or adjacent to existing lateral wellbores may be configured to diagnose the multi-lateral stimulation and production benefits. In one non-limiting example, the newer production lateral wellbores drilled may be labeled as “primary laterals” and the existing or older and already produced lateral wellbores as “assisting laterals” or alternatively “diagnostic laterals”. The in-fill new lateral wellbores could then be multi-laterally stimulated with use of the existing production lateral wellbores, where the new lateral wellbore is first near-wellbore fractured followed by then generating a conductive primary fracture into the older laterals' fracture network and/or to or very near the older laterals' wellbores, followed by release of treatment pressure through the older lateral wellbores to induce closure of the new primary lateral fracture network, and then eventually the older lateral wellbores are used to supply energy and mass or treatment fluid or cleanup fluid to clean-up the prior and/or the newly created fracture network, where the cleanup fluid and the residual treatment fluid is produced into the new primary lateral wellbore. By “in-fill” is meant a wellbore that is positioned between or more pre-existing wellbores.

The first drilling and producing conventional field lateral wellbores followed by later time in-fill lateral drilling may be advantageous for many reasons to the operator. The methods described here using diagnostic lateral wellbores can help diagnose factors including, but not necessarily limited to, (a) determining hydrocarbon production economics, (b) determining areas of the acreages and shale reservoir which may indicate having higher total hydrocarbon content, (c) lessons learned through different completion parameters (such as interval spacing, perforation spacing and density, and the like), (d) better indication of horizons of the shale interval that are the sweet spots, (e) better indication of which well treatments are effective for improved hydrocarbon production, and the like can play a role in a later in-fill drilling program that utilizes the bi-directional communication of laterals established between old and new lateral wellbores that are stimulated between the multiple lateral wellbores. All laterals, both old and new, can then potentially be producing laterals. There can be a wide range of variables in how the old laterals and perforated intervals are utilized in respect to the newly drilled adjacent laterals.

In another non-limiting example, the older lateral wellbores may be refractured followed by the new primary lateral stimulation process, where the re-stimulation includes a new in-fill completion process. In yet another non-limiting example, once the new lateral wellbore is stimulated and cleaned up through use of the older adjacent lateral wellbores, the older lateral wellbores can initially or later become the far-field complex fracture network in relation to the new primary lateral wellbore and its production characteristics. By using one or more diagnostic lateral wellbores, the in-fill process may also, in another non-limiting example, provide a wide range of diagnostic information in drilling, stimulating, closing, cleanup and production of the new in-fill primary lateral wellbores. The diagnostic information may be different or similar as compared to all adjacent lateral wellbores being newly drilled and non-produced prior to stimulation, treatment, closure and cleanup process by lateral-to-lateral communication established in multi-lateral completions as described herein. The more complete and more accurate information about processes and events downhole can have considerable economic value about how to better improve stimulation and completions of shale reservoirs in general or in geo-specific areas.

There are a multitude of suitable configurations for one or more diagnostic lateral wellbores in proximity to or adjacent to one or more primary lateral wellbores. Only a limited number can be described herein.

Turning to the Figures, FIG. 1 is a schematic, plan view of a series of shale intervals 21-25 in a subsurface volume or subterranean formation 30 along two primary lateral wellbores 34 and 44 and an assisting or diagnostic lateral wellbore 54, where complex fracture networks 40, 50, 60, 70, 80, 90, 100, and 110 substantially in the same fracture plane are schematically illustrated as extending from the primary lateral wellbores 34 and 44. Subsurface volume 30 may have different fracture planes substantially parallel to each other. Primary lateral wellbores 34 and 44 each extend from respective vertical wellbores 32 and 42 (seen from the top end) and have respective heel portions 36 and 46, and respective toes 38 and 48. Assisting or diagnostic lateral wellbore 54 extends from vertical wellbore 52 (seen from the top end) and has its own respective heel 56 and toe 58. The distance between respective heel portions and toe portions, for instance between 36 to 38, 46 to 48 and 56 to 58 is defined herein as lateral lengths, or lateral wellbore lengths.

Complex fracture networks 50 and 90 extend from perforations (not shown) in primary lateral wellbore 34 and primary lateral wellbore 44, respectively, toward assisting or diagnostic lateral wellbore 54 for interval 23. Complex fracture networks 70 and 110 extend from perforations (not shown) in primary lateral wellbore 34 and primary lateral wellbore 44, respectively, toward assisting or diagnostic lateral wellbore 54 for interval 24. It will be appreciated that for simplicity's sake the other intervals 21, 24, and 25 may also have complex fracture networks extending from primary lateral wellbores 34 and 44 toward assisting or diagnostic lateral wellbore 54. Complex fracture networks 40, 50, 60 and 70 are placed along the lateral length of primary lateral wellbore 34; complex fracture networks 80, 90, 100 and 110 are placed along the lateral length of primary lateral wellbore 44.

Through conventional fracturing techniques primary lateral wellbore 34 can be in fluid communication with assisting or diagnostic lateral wellbore 54 through complex fracture networks 50 and 70 through perforations or other orifices (not shown) in assisting or diagnostic lateral wellbore 54. Similarly, through conventional fracturing techniques primary lateral wellbore 44 can be in fluid communication with assisting or diagnostic lateral wellbore 54 through complex fracture networks 90 and 110 through perforations or other orifices (not shown) in assisting or diagnostic lateral wellbore 54. However, to assist in fluid communication between primary lateral wellbores 34 and 44 and assisting or diagnostic lateral wellbore 54 through complex fracture networks 50, 70, 90 and 110, there may be drilled a one or more fracture interval lateral wellbores 62 that extend a relatively short distance from assisting or diagnostic lateral wellbore 54 toward primary lateral wellbores 34 and 44, and that fracture interval lateral wellbores 62 may be in the same fracture plane as complex fracture networks 50, 70, 90 and 110. Fracture interval lateral wellbores 62 may be provided with a plurality of perforations, holes and/or orifices to communicate with the respective adjacent complex fracture network and thus provide fluid communication therewith. These fracture interval lateral wellbores 62 may be of “moderate length”, which in one non-limiting embodiment is defined as from about 20 to about 200 feet (about 6 to about 61 meters) or may be of different lengths.

Also shown in FIG. 1 are a plurality of diagnostic lateral wellbores 64 extending from assisting or diagnostic lateral wellbore 54 above and over primary lateral wellbore 34 and a plurality of diagnostic lateral wellbores 66 extending from assisting or diagnostic lateral wellbore 54 above and over primary lateral wellbore 44. Additionally shown in FIG. 1 are a plurality of diagnostic lateral wellbores 72 extending from assisting or diagnostic lateral wellbore 54 below and under primary lateral wellbore 34 and a plurality of diagnostic lateral wellbores 74 extending from assisting or diagnostic lateral wellbore 54 below and under primary lateral wellbore 44.

It will be appreciated that there are a myriad of ways that primary lateral wellbores and assisting or diagnostic lateral wellbores can be configured with respect to each other. In FIG. 1 primary lateral wellbores 34 and 44 and assisting or diagnostic lateral wellbore 54 are generally in the same fracture plane and are generally parallel to one another. However, diagnostic lateral wellbores 64 and 66 are generally in the same fracture plane as each other, but above the fracture plane that primary lateral wellbores 34 and 44 and assisting or diagnostic lateral wellbore 54 reside in. Similarly, diagnostic lateral wellbores 72 and 74 are generally in the same fracture plane as each other, but below the fracture plane that primary lateral wellbores 34 and 44 and assisting or diagnostic lateral wellbore 54 reside in. However, viewed from above as in FIG. 1, diagnostic lateral wellbores 64, 66, 72 and 74 are seen as perpendicular to primary lateral wellbores 34 and 44 and assisting or diagnostic lateral wellbore 54.

Various combinations and configurations of primary lateral wellbores and assisting or diagnostic lateral wellbores may be envisioned beyond and different from those illustrated in FIGS. 1-3. Non-limiting embodiments include multiple primary lateral wellbores and multiple diagnostic lateral wellbores that are interdigitated with each other, either in the same horizontal or fracture plane or in different horizontal or fracture planes. They may be substantially parallel to one another, or if in different horizontal or fracture planes, they may be at angles relative to one another when viewed from above or below, in another non-limiting instance at right angles or generally perpendicular, such as that seen in FIG. 1. The primary lateral wellbores and/or diagnostic lateral wellbores may each branch or extend from their individual respective vertical wellbores, or alternatively a single vertical wellbore may have more than one primary lateral wellbore and/or more than one diagnostic lateral wellbore extending therefrom. Other suitable configurations are depicted in U.S. patent application Ser. No. 14/870,880 filed Sep. 30, 2015 and Ser. No. 15/147,449 filed May 5, 2016.

In non-limiting embodiments, when at least one diagnostic lateral wellbore is substantially adjacent to and/or proximate to the primary lateral wellbore, this is defined herein as within about 50 independently to about 600 feet (about 15 independently to about 183 meters) of each other, alternatively within about 100 independently to about 400 feet (about 30 independently to about 122 meters) of each other. “Substantially parallel” is defined herein as within 0° independently to about 45° of the same angle as each other; within 0° independently to about 20° of the same angle as each other; alternatively within from about 0° independently to about 5° of each other. The term “independently” as used herein with respect to a range means that any lower threshold may be combined with any upper threshold to give a suitable alternative range. As will be explained and shown, however, the adjacent diagnostic lateral wellbore need not be parallel to the primary lateral wellbore and the subsurface volume that is being diagnosed.

In one non-limiting version of the FIG. 1 embodiment a diagnostic agents, such as tracers, are injected through the diagnostic lateral wellbore 54 into fracture interval lateral wellbores 62 into complex fracture networks 70 and 110, 50 and 90 and to be produced with produced hydrocarbons through primary lateral wellbores 34 and 44 for evaluation of the production from frac intervals 22 and 23, respectively. By isolating the intervals (e.g. 22 and 23), different diagnostic agents may be introduced into different intervals and comparisons between the complex fracture network may be done to see if one interval is relatively more or less productive. If the intervals were fractured and/or treated differently one from the other, a judgment could be made about which fracturing technique and/or which well treatment was more advantageous than another. Thus, the fracturing technique that is more successful may be used instead, or the well treatment that is more advantageous than the others may be used instead. In one non-limiting embodiment the diagnostic agent is introduced into the at least one lateral wellbore at least once every three independently to six months; alternatively at least once every one independently to thirty days. In a different non-restrictive version, treatment fluids may also be introduced on such a schedule. These introduction schedules may be periodic, intermittent, or a combination thereof.

Using configurations such as those illustrated in FIGS. 1-3, reservoir production fluids can be mapped to observe frac interval production over time. In the case of evaluating the production of multiple intervals, placement of treating chemical injection points along the diagnostic laterals (which in one non-limiting embodiment are parallel to the primary or producing lateral) or from frac interval laterals positioned within the complex fracture network can be used for injecting small amounts of interval-specific, or “one interval at a time” tracers or other diagnostic agents for analysis of the flowback fluid once at the surface. This method is a significant improvement over the current practice of using tracers in frac treatments that have limited duration of use, whereas utilizing diagnostic lateral wellbore injection locations can provide life-of-well production information for each interval. Additionally, evaluation of possible causes for reservoir fluid production drop-off or reduction can be diagnosed through injection of diagnostic fluids, such as solvents to remove inorganic scale, paraffin and asphaltene solvents, polymer residue cleanup solutions, waterblock removal solutions, and the like and observe the reservoir production response.

Shown in FIG. 2 is a schematic, horizontal cross section of the subsurface shale volume 30 showing the two primary lateral wellbores 34 and 44 an imaging or diagnostic lateral wellbore 54 (see end-on), where upper imaging lateral diagnostic wellbores 64 and 66 and lower imaging lateral diagnostic wellbores 72 and 74 are shown, as viewed from line 2-2 in FIG. 1. The same reference numerals are used in FIG. 2 for the same elements as in FIG. 1. FIG. 2 shows a cross-section or “slice” of one interval. Fracture interval lateral wellbores 62 extend from either side of diagnostic lateral wellbore 54. From this FIG. 2 it may be seen that the two primary lateral wellbores 34 and 44 and the imaging or diagnostic lateral wellbore 54 are all in the same fracture plane. Although complex fracture networks are not shown in this view, perforations 76 are schematically shown on primary lateral wellbores 34 and 44, from which perforations 76 the fracturing fluid would forcibly exit the primary lateral wellbores to form the complex fracture networks 40, 50, 60, 70, 80, 90, 100, and 110. Once more, moderate length fracture plane oriented injection laterals 62 can be used to place diagnostic materials, such as tracers for evaluation of frac interval fluid production.

In another non-limiting embodiment, FIG. 3 is a schematic, three-quarters view illustrating two vertical wellbores 330 and 334 directionally drilled to respective primary lateral wellbores 344 and 348 extending therefrom and a third vertical wellbore 332 directionally drilled to an assisting or diagnostic lateral wellbore 346 through subsurface volume 342 that has upper diagnostic lateral wellbores 350 and lower diagnostic lateral wellbores 352 extending therefrom over and under the primary lateral wellbores 344 and 348, respectively.

In more detail for FIG. 3, the left primary lateral wellbore 344 and the right primary lateral wellbore 348 having a diagnostic lateral wellbore 346 between them are all in the same generally horizontal plane; namely a fracture plane. Three fracture intervals 23, 24 and 25 are shown for the purposes of simplicity, although a plurality of further fracture intervals beyond 23 may be easily imagined. Diagnostic lateral wellbore 346 has a plurality of upper imaging diagnostic lateral wellbores 350 extending up and over the left and right primary lateral wellbores 344 and 348, respectively, in an upper horizontal plane, as well as a plurality of lower imaging diagnostic lateral wellbores 352 extending down and under the left and right primary lateral wellbores 344 and 348, respectively, in an upper horizontal plane. Diagnostic lateral wellbore 346 and upper imaging diagnostic lateral wellbores 350 have a plurality of acoustic generators 354 placed therein, and lower imaging diagnostic lateral wellbores 352 and primary lateral wellbores 344 and 348 have a plurality of acoustic sensors 356 placed therein.

Diagnostic lateral wellbore 346 has fracture interval laterals 358 of moderate length in the fracture plane for fracture network diagnostic, treatment, closure and/or cleanup functions. By “in the fracture plane” is meant that complex fracture networks (not shown) are generated from primary lateral wellbores 344 and 348 via perforations therein (not shown). By “moderate length” again is meant from about 20 to about 200 feet (about 6 to about 61 meters).

In the FIG. 3 configuration, the evaluation of treatment fluid movement and removal can be compared to neighboring frac intervals (23, 24, 25) by placing diagnostic lateral wellbores 346 around and in the hydraulic fracture networks (not shown for clarity) followed by injection of CO₂ gas, e.g., from the far-field parallel diagnostic lateral wellbore (not shown, but in a non-limiting example a diagnostic lateral wellbore to the left of primary lateral wellbore 344 and a diagnostic lateral wellbore to the right of primary lateral wellbore 348) and/or from the fracture interval laterals 358 extending from the parallel diagnostic lateral wellbore 346. Imaging the real-time gas placement process (i.e. displacement of treatment fluid in fractures) may show regions of the hydraulic fracture system that did not effectively clean up on their own (i.e. compared to data from neighboring intervals). Thus, diagnostic evaluation of the degree of fracture network system cleanup can be determined for geo-specific shales, including processes, parameters and/or treatment materials for improved treatment fluid load recovery and for determining the related impact and/or importance load recovery on improving reservoir hydrocarbon production.

The diagnostic cleanup fluid may be any suitable treatment fluid, such as an inert gas, e.g. nitrogen (N₂) or carbon dioxide (CO₂), light brines like 2% KCl, other types aqueous fluids containing formation and/or fracture cleanup chemicals, such as but not necessarily limited to: clay inhibitors, KCl substitutes, clay control agents, corrosion inhibitors, iron control agents, mutual solvents, water wetting surfactants, foaming agents, microemulsion cleanup agents, alkyl silanes and/or other hydrophobic inducing agents to plate on the walls of the fracture and/or on the proppants, biocides, polymer breakers, tracers or tracing agents, non-emulsifiers, reducing agents, chelants such as aminocarboxylic acids and salts thereof, organic acids, esters, resins, mineral acids, viscoelastic surfactants, internal breakers for VES fluids such as mineral oils and/or natural plant and fish oils high in unsaturated fatty acids, polymeric-based friction reducers, inorganic nanoparticles, organic nanoparticles, salts, organic scale inhibitors, inorganic scale inhibitors, slow release scale inhibitor agents like ScaleSORB™ available from Baker Hughes, pH buffers, and the like and combinations thereof.

In shale reservoir cleanup after hydraulic fracture treatments, a return of 10-20 vol % of the hydraulic fracture treatment fluid is considered typical or average. The rest of the fluid is retained in the formation for various reasons and may cause formation damage of various types that restrict and/or reduce hydrocarbon production immediately and/or sometime after the fracture treatment. Many geo-specific reservoirs may be highly sensitive to the amount of residual treatment fluid left in the fracture network. The diagnostic cleanup treatment methods presented herein can help increase the unloading percentages of the treatment fluids, thus helping remove as much fluid as possible to inhibit or prevent or reduce them from causing possible damage. Learning how to obtain returns of about 30 vol % or more, alternatively about 40 vol % or more, and in another non-limiting embodiment about 60 vol % or more are expected with the configurations and methods described herein.

It should be appreciated that the use of diagnostic or imaging lateral wellbores can have a significant benefit for injecting and distributing treatment fluids and materials within complex fracture networks that surpass conventional injection at the primary lateral perforations. Treatment fluids or treating chemicals for production optimization, such as water-block removal, fines migration removal, treating chemicals for prevention of scale and paraffin deposition, chemicals for the removal of residual polymer, chemicals for the removal of inorganic scale, chemicals for the removal of organic deposits, and/or diverter materials can be injected along the diagnostic lateral wellbores and/or fracture interval lateral wellbores and have broader and/or deeper distribution into the fracture network. Treatment techniques can also improve fluid or chemical distribution, such as use of gas injection to help energize fluid flow toward the primary lateral wellbore(s) during production optimization treatments. The value to the industry of the diagnostic lateral wellbores and fracture interval lateral wellbores can be substantial for shale and other unconventional reservoirs that require frequent remedial treatments.

Further, the shale completion industry is continually evaluating the economic justification for refracturing treatments. The ability to image existing hydraulic fractures versus newly-created hydraulic fractures, and the ability to optimize treatment designs through diagnostic treatments and imaging process, can have significant importance for the refracturing business market. Of particular importance, diagnostic fracturing techniques can be imaged to determine how produced reservoirs react to particular refracturing techniques. In one non-limiting example, a lower rate injection of gas initially can be used to expand reservoir fractures for imaging existing fracture networks. Diagnostic frac treatments can then be performed to determine the treatment parameters that control new fracture generation, fluid diversion, fracture complexity, and how to best distribute proppant into the new and/or existing hydraulic fracture network. The amount and quality of information generated by using various imaging techniques, diagnostic hydraulic treatment techniques/processes/materials, and diagnostic lateral wellbore placement and configurations can be significant in the shale refrac market.

While all of these wells 34, 44, 54, 344, 346 and 348, may eventually be producing wells once completion is accomplished, it is expected that primary lateral wellbores 34 & 44 and 344 & 348 will be the primary producing wellbores for understanding how particular diagnostic treatment processes and conditions may influence positively or negatively the cleanup and producibility of geo-specific reservoirs.

Alternatively, fracture interval outer laterals, such as 62 extending from parallel diagnostic lateral wellbore 54, and fracture interval outer laterals 358 extending from parallel diagnostic lateral wellbore 346 can be injection points for gas, slickwater and the like during a fracturing treatment to control far-field complex fracture development, i.e. as in a dual frac treatment process. The rate, volume, etc. of the injection from the frac interval laterals 62 and 358 can be varied or customized for each interval and the shale interval rock response, fracture complexity, fracture network geometry and the like may be observed using diagnostic devices described herein. Also of particular importance are parameters that control treatment fluid diversion and distribution, such as type and amount of chemical diverter material, staged or continuous addition of diverter, viscosity of fluids, staging and volumes of the fluids, fluid pump rates, presence of natural fissures in the shale and the like. Methodical diagnostic treatments can be performed to determine factors which create near wellbore fracture network complexity, far-field fracture complexity capability, and the like. An important part of changing diagnostic treatment parameters may be finding the parameters that promote optimum treatment fluid interaction with reservoir natural fractures and anisotropy stresses laterally and/or vertically in the reservoir.

It will be appreciated that the fracture interval outer laterals 62 and 358 may be used for a wide variety of purposes and methods, including, but not necessarily limited to, imaging, dual fracturing, forced closures of fracture networks, fracture cleanup, tracer and remedial injections, refracturing treatments and combinations of these methods—most likely in a sequential order.

Besides being used for mapping hydraulic fracture/natural fracture interaction during hydraulic fracturing treatments, and related flow and distribution of hydraulic fracturing fluid and materials during diagnostic hydraulic fracturing treatments in geo-specific shales, the cleanup of hydraulic fracturing fluids can potentially be mapped in 2D and/or 3D through the combined use of diagnostic lateral wellbores (such as 64, 66, 72 and 74 in the FIG. 2 embodiment, and 350 and 352 in the FIG. 3 embodiment), reservoir imaging instruments and diagnostic cleanup procedures and materials. The importance of complex fracture interval cleanup may be a larger issue for the productivity of shale reservoirs than many operators recognize, and the generation of information on network cleanup may be very valuable to the industry. It may be possible that laterally assisted forced fracture network closure along with laterally assisted displacement methods and treatments may show which geo-specific shale regions may require dual-bore treatments to achieve maximum hydrocarbon production and maximized return on investment (ROI).

In a different area of concern, the toe to heel multi-interval fracture process isolates the lower frac zones upon treatment completion, leaving the hydraulic fracture networks created to “close” on their own over time. In many cases, since shales typically have nano-darcy permeability, fracture closure time often takes days to weeks. During these extended time periods extreme proppant settling and loss of vertical fracture conductivity in the upper half of the fractures occurs. Hydraulic fracture and proppant imaging techniques can be used in combination with pressure release tools that can be activated in diagnostic lateral wellbores, and fracture lateral wellbores which extend from the parallel diagnostic lateral wellbores.

Locations of the pressure release points along the diagnostic lateral wellbores can be configured to influence the areas which see closure more quickly. Primary propped fracture locations may be favorable locations for initiating fracture network closure. Variation in closure locations and closure times can be evaluated on degree of proppant settling. For example, conductive proppant can be imaged by electrolocation techniques. Variations in the size of the proppants or conductive particles can be utilized to determine how closure time may potentially vary within the fracture network system. If the primary lateral wellbores are placed lower in the shale interval than imaging determined information show the locations of a higher permeability or hydrocarbon sweet-spot horizon, then the result will be that the slow natural closure time and resultant extensive proppant settling will more significantly adversely affect reservoir productivity since the sweet-spot horizon fracture closed without proppant present.

It will be appreciated that fracture interval outer laterals 62 and 358, in non-limiting embodiments) may be of moderate length (about 10 to about 100 feet; about 3 to about 30 meters) for inducing fracture network closure, or may be of extended length (about 100 to about 300 feet; about 30 to about 91 meters) for inducing fracture network closure at a greater distance and/or over a wider area.

Dual fracturing, or dual-injection of frac systems, is injection from two or three adjacent lateral wellbores where treatment fluid and fracture networks approach and eventually interact with each other. The injection rates, type of fluid, viscosity of fluid, and stop-start staging of fluid injection may vary from the adjacent wellbores, with parameters and conditions varied to gain diagnostic-based insight of how the reservoir properties and fracture networks may be geometrically controlled and the frac interval reservoir area may be more optimally stimulated. That is, the size, amount, distribution and the like of the hydraulic fractures and related propped and non-propped conductivity is generated within the frac interval. This significantly differs from “mono-bore” fracture stimulation methodology for learning how to optimize reservoir stimulated rock volume and related hydrocarbon productivity from geo-specific shales.

There are a number of known imaging techniques that may be implemented in the methods and configurations for diagnosing subsurface volumes containing at least primary lateral wellbore, including, but not necessarily limited to the following.

A. R. Rahmani, et al. in “Crosswell Magnetic Sensing of Superparamagnetic Nanoparticles for Subsurface Applications,” SPE 166140, SPE Annual Technical Conference and Exhibition, New Orleans, La., USA, 30 Sep.-2 Oct. 2013 discloses that stable dispersions of superparamagnetic nanoparticles are capable of flowing through micron-size pores across long distances in a reservoir having modest retention in rock. These particles can change the magnetic permeability of a flooded region, and thus may be used to enhance images of the flood. Propagation of a “ferrofluid slug” in a subsurface volume through primary lateral wellbores may have its response monitored by a crosswell magnetic tomography system as described in this paper. This approach to monitoring fluid movement within a reservoir is built on established electromagnetic (EM) conductivity monitoring techniques.

U.S. Pat. No. 8,253,417 to Baker Hughes Incorporated, discloses an electrolocation apparatus useful for determining at least one dimension of at least one geological feature of an earthen formation from a subterranean well bore which includes at least two electric current transmitting electrodes and at least two sensing electrodes disposed in the well bore. The electric current transmitting electrodes are configured to create an electric field and the sensing electrodes are configured to detect perturbations in the electric field created by at least one target object. This electrolocation apparatus and method can approximate or determine at least one dimension of geological features such as hydraulic fractures.

S. Basu, et al., in “A New Method for Fracture Diagnostics Using Low Frequency Electromagnetic Induction,” SPE 168606, SPE Hydraulic Fracturing Technology Conference, the Woodlands, Tex., USA, 4-6 Feb. 2014 discloses that at the time of the article, microseismic monitoring is widely used for fracture diagnosis. Since the method monitors the propagation of shear failure events, it is an indirect measure of the propped fracture geometry. The primary focus of the paper is in estimating the orientation and length of the “propped” fractures (in contrast to the created fractures), since this is the principal driver for well productivity. The paper presents a new Low Frequency Electromagnetic Induction (LFEI) method which has the potential to estimate not only the propped length, height and orientation of hydraulic fractures, but also the vertical distribution of proppant within the fracture. The proposed technique involves pumping electrically conductive proppant into the fracture and then using a specially built logging tool that measures the electromagnetic response of the formation. Results are presented for a proposed logging tool that consists of three sets of tri-directional transmitters and receivers at 6, 30 and 60 feet spacing, respectively (1.8, 9.1 and 18 m, respectively). The solution of Maxwell's equation shows that it is possible to use the tool to determine both the orientation and the length of the fracture by detecting the location of these particles in the formation after hydraulic fracturing. Results for extensive sensitivity analysis are presented to show the effect of different propped lengths, height and orientation of planar fractures in a shale formation. Multiple numerical simulations, using a leading edge electromagnetic simulator (FEKO), indicate that fractures up to 250 feet (76 m) in length, 0.2 inches (0.5 cm) wide and with a 45° of inclination may be detected and mapped with respect to the wellbore.

Shown in FIG. 3 is a schematic, three-quarters sectional view of a subsurface volume 342 illustrating two parallel primary lateral wellbores 344 and 348, and fracture plane oriented imaging diagnostic lateral wellbore 346 extending substantially parallel to them and between them. Extending perpendicularly from imaging diagnostic lateral wellbore 346 up and over the two parallel primary lateral wellbores 344 and 348 at approximately the boundaries each of fracture intervals 23, 24, and 25 are upper imaging diagnostic lateral wellbores 350. Extending perpendicularly from imaging diagnostic lateral wellbore 346 below and under the two parallel primary lateral wellbores 344 and 348 at approximately the boundaries each of fracture intervals 23, 24, and 25 are lower imaging diagnostic lateral wellbores 352. It may be easily imagined that the fracture intervals 23, 24 and 25 have complex fracture networks extending from the primary lateral wellbores 344 and 348 toward the diagnostic lateral wellbore 346 in the manner illustrated in FIG. 1, and the complex fracture network pattern and/or geometry can be highly variable and particular to the geo-specific shale geomechanical properties, diagnostic treatment parameters, and the like. Conductive proppant (not shown) would be injected into the complex fracture networks. It will be understood that as a practical matter, it could not be expected that all of each of the complex fracture networks would be filled with conductive proppant; that is, it is more likely that the fracture networks would be only partially filled or mostly filled with proppant. Electrolocation apparatus, such as those described above, for instance acoustic generators 354 and acoustic sensors 356, would be placed in the fracture plane oriented diagnostic lateral wellbores 350 and 352, respectively to measure the length, width and orientation of the fractures of complex fracture network generated for the geo-specific rock and specific fracture treatment conditions. Thus, FIG. 3 is one of many possible configurations in which methods for diagnosing, including fracture development and/or proppant placement imaging, within subsurface volumes containing at least one primary lateral wellbore (e.g. 344 and/or 348) that is adjacent to at least one diagnostic lateral wellbore (346) may be practiced for understanding how to stimulate shale reservoirs, and geo-specific shales in particular. More specifically, diagnostic devices (e.g. 354 and 356) may be placed in fracture plane oriented diagnostic lateral wellbores (e.g. 350 and 352, respectively) to emit at least one signal to or through subsurface volume 342, a received signal may be detected by the same or different diagnostic device, and the received signal may then be analyzed to ascertain or determine or measure at least one parameter of the at least one primary lateral wellbore 344 and/or 348 and/or the subsurface volume 342. In one non-limiting example, the FIG. 3 configuration may be used for imaging the dynamic placement and distribution of proppant within a geo-specific shale during a fracture treatment using select treatment parameters.

FIG. 2 provides a non-limiting alternate embodiment for imaging subsurface volume 30 using a plurality of acoustic generators 1-24 in diagnostic lateral wellbores 64 and 66, as well as acoustic generator 82 on diagnostic lateral wellbore 54 in conjunction with a plurality of acoustic sensors 68 on diagnostic lateral wellbores 72 and 74. These acoustic generators 1-24 and 82 and acoustic sensors 68 would function similarly to those described above.

It will be appreciated that acoustic generators 354, 83 and 1-24, and acoustic sensors 356 and 68 are simply one typical imaging tool, and that other types of imaging tools, such as those described elsewhere herein, and others, may be employed.

The methods and configurations of primary lateral wellbores and diagnostic lateral wellbores may take advantage of microseismic fracture mapping. For instance, R. Downie, et al. in “Utilization of Microseismic Event Source Parameters for the Calibration of Complex Hydraulic Fracture Models,” SPE 163873, SPE Hydraulic Fracturing Technology Conference, the Woodlands, Tex., USA, 4-6 Feb. 2014, notes that observations of microseismic events detected during hydraulic fracturing treatments have provided an incentive to develop complex fracture models. Calibration of these models may be difficult when only the locations and times of the microseismic events are used. Incorporating the microseismic event source parameters into the model calibration workflow reveals changes in fracture behavior that are not easily visualized and provides additional guidance to the selection of modeling parameters. Microseismic events occur when deformation of the reservoir and surrounding formations produces seismic waveforms. Hodogram analysis and travel-time of the recorded waveforms are used to locate the microseismic event sources, while the amplitudes and polarities of the waveforms provide information about the deformation that has occurred. The geophysical property that is derived from the wave amplitudes is known as the seismic moment and is related to the area and displacement of the failure.

The relationship between seismic moment values and the deformations that produced microseismic events may be applied to engineering evaluations to identify variations in microseismic response. Use of this source parameter supplements commonly used visualizations of microseismic response where microseismic activity has been mapped. Mapping of the seismic moment distributions in a three-dimensional viewer provides insights into fracture behavior that can be used to calibrate complex hydraulic fracture models. This is done through an integrated software package that facilitates comparisons of the microseismic evaluation and complex fracture modeling outputs seamlessly. Changes to the complex fracture model inputs can be evaluated easily and quickly to determine if the fracture modeling correlates well with the measured microseismic responses. Production evaluation, history-matching and forward-modeling to test different completion and stimulation design scenarios can be undertake with improved confidence using the calibrated fracture model. The complex fracture models of SPE 163873 may be improved by using the methods and configurations of at least one primary lateral wellbore adjacent at least one diagnostic lateral wellbore described herein.

The methods and configurations of at least one primary lateral wellbore adjacent at least one diagnostic lateral wellbore which are described herein may also find utility in induced acoustic wave fracture mapping or micro-imaging. “Micro-imaging” is defined herein as image data collected on the scale of a single fracture interval. This technique may use low-frequency high energy (LFHE) (also called low-frequency high intensity or LFHI) acoustic generators in one or more diagnostic lateral wellbore and an array of low-frequency sensors in one or more primary lateral wellbore. The use of sequential or alternate pulse, duration and frequency sweeps of acoustic generator signals (wave propagations) in the high to ultra-high resolution generator-rock-sensor configurations described herein provide greater data clarity and/or degree of resolution for real-time hydraulic fracture generation mapping during fracture treatments, and may give 2D and/or 3D graphic displays of complex fracture networks. The high resolution mapping of complex fracture network generation should provide empirical data of hydraulic fracture-natural fracture interactions for calibrating fracture and reservoir models for improving geo-specific shale stimulation and production.

One non-limiting way of how this may be accomplished is described by A. Bolshakov, et al. in “Deep Fracture Imaging Around the Wellbore Using Dipole Acoustic Logging,” SPE 146769, SPE Annual Technical Conference and Exhibition, Denver, Colo., US, 30 Oct.-3 Nov. 2011, which discloses that characterizing fractures in reservoir rocks is important because they provide critical conduits for hydrocarbon production from the reservoir into the wellbore. The standard method uses shallow borehole imaging services, both acoustic and resistivity, which essentially look at the intersection of the fractures at the borehole wall. Cross-dipole technology has extended the depth of evaluation some 2-4 ft (0.6-1.2 m) around the borehole by measuring the fracture-induced azimuthal shear-wave anisotropy. A recently developed shear-wave reflection imaging technique provides a method for fracture characterization in a much larger volume around the borehole with a radial extent of approximately 60 ft (18.3 m). This technique uses a dipole acoustic tool to generate shear waves that radiate away from the borehole and strike a fracture surface. The tool also records the shear reflection from the fracture. The shear-wave reflection, particularly the SH waves polarizing parallel to the fracture surface, is especially sensitive to open fractures, enabling the fractures to be imaged using this dipole-shear reflection data. (SH waves are shear waves that are polarized so that its particle motion and direction of propagation are contained in a horizontal plane.) The authors used case examples to demonstrate the effectiveness of this shear-wave imaging technology that maps fractures up to 60 ft (18.3 m) away and even detects fractures that do not intercept the borehole.

Induced acoustic wave fracture imaging of cross-sections of subsurface volumes can be accomplished using one or more diagnostic lateral wellbores horizontal and/or parallel to one or more primary lateral wellbores adjacent to each other. Such adjacent relationships are described and/or schematically illustrated and described throughout the specification. In a non-limiting embodiment, a diagnostic lateral wellbore may have two low frequency, high energy (LFHE) acoustic generators per fracture interval. Further, the primary lateral wellbore may have an array of acoustic sensors therein emitting and detecting signals through the complex fracture networks. LFHE acoustic generators and acoustic sensors are non-limiting examples of diagnostic devices suitable for use in the methods and configurations described herein. Changes in baseline signal transit time to each sensor indicates the presence of a fracture, such as in complex fracture networks. Working with transit time angles of the signals from each generator to each sensor can indicate fracture size, growth, branching and horizontal network geometry over time.

The acoustic waves generated will have relatively short distances to travel through the shale interval (as contrasted with conventional approaches using only adjacent substantially vertical wellbores) so that the signal type, intensity, amount of distortion and the like will encounter less rock minerals, pores, fluids, natural fractures and the like and thus provide improved information quality, particularly with the control of the intensity, duration, pulse timing, and the like, of the acoustic wave generators for acquiring baseline and changes to the reservoir and hydraulic fractures over time. In other words, the LHFE acoustic generators can be positioned in various diagnostic lateral wellbores with low frequency sensors in adjacent lateral wellbores to give better sampling measurements of the speed, reflection, refraction and the like of acoustic waves for better understanding of the localized shale interval properties and characteristics. The configurations of wellbores and methods described herein will also employ imaging technology that can measure how fractures propagate in specific shales, i.e. how they differ from one shale to another for a given set of treatment parameters. Shale reservoirs in general have differing physical, chemical and mechanical characteristics from each other. How hydraulic fractures are generated and propagated in one shale reservoir compared to another will differ geographically, even under the same given set of hydraulic fracturing treatment parameters. Thus, the knowledge gained using the configurations and methods described herein can be important to learn how each shale reservoir should be hydraulically fractured for optimum fracture complexity, surface area generated, number of propped fractures, distribution of proppant, better understanding of fracture network conductivity generated, how to determine the select areas of the reservoir that show higher permeability and related criteria for determining the location of hydrocarbon sweet-spot horizons, and the like.

It will be appreciated that when more acoustic generators 1-24, 82, and 354, and more acoustic sensors 68 and 356 are used, the acoustic imaging resolution of the subsurface volumes 30 and 342 may be greatly increased due to the greater number of signals employed. For instance, in FIG. 2, each acoustic generator 1-24 and 82 can be detected by multiple acoustic sensors 68, and as one non-limiting example, each acoustic generator 1-24 and 82 is pulsed in intensity, duration, frequency, and time-stamped in sequential series (such as pulsation of generator 1, then generator 2, then generator 3, etc.) for data collected by acoustic sensors 68 for pretreatment (i.e. baseline), during the treatment, and post treatment for characterizing, including, over time, dynamic growth of hydraulic fractures and related fracture networks, and rock stress alterations within the interval for determining and understanding how geo-specific shales respond to select treatment parameters and processes. To date, no diagnostic methodology for shale horizontal completions can provide this type and quality of information, as described in this non-limiting example of acoustic signal transmission duration, acoustic signal transmission magnitude (i.e. amount of acoustic energy transmitted in combination with the frequency of the acoustic wave, such as variation that can include more detectable high-intensity low-frequency acoustic waves utilization), methodology of coordinating signal transmission timing along an array of acoustic generators, process of angulation signal collection (the process of one acoustic generator signal transmission at a time that is then collected by numerous acoustic sensors in an array in spatial distribution (i.e. multiple transmission paths data collection per acoustic generator correlation by angulation), and processing during and after diagnostic-based treatments. The degree of signal resolution within the treated interval is very important to obtaining data that can provide 2D and/or 3D visualization of developed hydraulic fracture networks, and the data needed in order to calibrate fracture models to have predictive skill for other treatments in the geo-specific shale area, that is, considerable acquired understanding (substantially increased learning rate) about how to develop optimized geometric fracture networks in geo-specific shales compared to past trial and error methodology of a slow learning curve and sometimes years of extended treatment cost investment before learning how to properly stimulate and complete the targeted reservoir. One non-limiting example of elaborate investment costs and a significantly slow learning curve is recognized by the type of fracture treatment designs (materials, volumes, and processes) utilized in the Eagle Ford shale in 2008 versus in 2010 versus in 2015.

With respect to wildcat wells used to locate shale sweet-spots in new geologic or geo-specific shale plays, a significant amount of work and expense is put forth to find where and how to complete the shale interval with best success for economic ROI. Most new play operators need to drill, stimulate and produce well over ten lateral wells to learn the minimum basics of shale geographic characteristics and suitable stimulation methods for best achieving an economic shale play. For this reason, operators need to acquire a suite of information in their initial field evaluation and development phases. Discussed herein are methods to help operators obtain important reservoir and stimulation technique information in a shorter period of time, which also reduces risks in knowing field and interval production potential. Diagnostic lateral wellbores can be used with imaging techniques and diagnostic-based treatments to generate important drilling and completion information for operators evaluating a new geo-specific shale play. For example, when drilling a vertical well to then further drill evaluation lateral wellbores, methods and techniques are proposed where the evaluation laterals do not need to be as long in length, and where one or more diagnostic lateral wellbores are drilled in various configurations adjacent to primary laterals for the purpose of acquiring important information at a faster rate about the reservoir interval and effectiveness of fracturing treatment parameters to generate complex fracture networks, sweet-spot horizon determination, requirements for fracture network cleanup, additional diagnostic information on lateral and vertical heterogeneity of shale rock lithology, petrophysical properties, geomechanical properties, natural fissure properties, hydraulic fracture-natural fracture interactions, methods to optimize natural fracture dilation and extension, best geo-specific practices for acquiring near-wellbore and far-field complex fracture networks, best geo-specific practices for selection and use of proppants for achieving transitional nano-to-micro-to-milli-to-macro darcy conductivity versus abrupt nano-to and/or micro-to-macro darcy conductivity within the complex fracture network, and the like. “Nano-to-micro-to-milli-to-macrodarcy conductivity” refers to efforts to improve conductivity from a nano-darcy-characterized permeability through microdarcy, millidarcy, and macrodarcy permeabilities.

The diameter of the diagnostic wellbores can be of any size, including coiled tubing drilled slim diameter wellbores. Additionally, the primary lateral and potential diagnostic lateral wellbores can be cased and/or openhole, including various combinations thereof. In one non-limiting example, openhole casing packers with select location of ports, sliding sleeves, and/or removable perforation plugs can be run in the hole during the wellbore completion process, including location of communication and/or signal generator and sensors at the surface before or as the casing is run in the primary and/or potential diagnostic lateral wellbores.

It will be appreciated that diagnostic devices, including but not necessarily limited to, acoustic generators and acoustic sensors, may be placed in diagnostic lateral wellbores and/or relatively shorter primary lateral wellbore to analyze one or more parameter to ascertain at least one parameter of relatively shorter primary lateral wellbore and the subsurface volume around it, including, but not limited to, whole and/or stratified lithology parameters of subsurface volume, a hydraulic fracture treatment or treatments of induced complex fracture network(s) adjacent relatively shorter primary lateral wellbore. These parameters can provide more precise information about how to find and recover hydrocarbons, that is, the best geo-specific hydraulic fracturing process for generating near-wellbore and/or far-field complex fracture networks, the best geo-specific treatment fluid recovery process, the best or better understanding of differences of geo-specific wellbore completion options and processes (i.e. the amount and distance a part of sliding sleeves and/or perforation clusters, the size of frac interval and number of perforation clusters, the effectiveness of multi-cluster breakdown and hydraulic fracture stimulation of geo-specific shale), and the like from subsurface volume. Combination of the methods described herein with known diagnostic tools and measurements, such as fiber optic sensing technologies like Distributed Temperature Sensing (DTS) and Diagnostic Acoustic Sensing (DAS), microseismic, wellbore and reservoir logging tools, and the like can improve the amount and accuracy of knowledge gained during the wildcat drilling, completion, and production process.

The ascertained parameters can provide more precise information about how to find and recover hydrocarbons from subsurface volume. Like with other lateral wellbores in the other illustrations, the primary and more particularly the diagnostic lateral wellbores may be coiled tubing drilled slimholes, as non-limiting examples of singular and/or combinations of drilling and completions of lateral wellbores illustrated and disclosed herein.

It should be appreciated that the methods and configurations of at least one diagnostic lateral wellbore with at least one primary lateral wellbore may be used to evaluate stress shadow effects on fracture propagation direction and complexity. A “stress shadow” may be defined as a region or area on either side of a primary lateral wellbore formed by pressure injection. This stresses the rock in a lateral direction to provide more control in fracturing the shale. For bi-direction fracturing treatments, there is provided a number of control of region, timing, interaction, and the like stress shadow utility and/or control options, in one non-limiting embodiment, the fracturing from the primary lateral wellbore may be initiated first and then stopped, followed by pumping from a diagnostic lateral wellbore and/or a parallel assisting lateral wellbores in one or more cycles, rather than simultaneously. In one non-limiting embodiment this kind of stop/start-low viscosity/high viscosity staged diversion process may be used to create complex fractures. That is, pumping a relatively low viscosity fracturing fluid, stopping the pressure, then pumping a relatively high viscosity fracturing fluid may be used alternatingly or in cycles to create complex fracture networks. Imaging and/or diagnostic devices can be arranged to capture the directions, propagations, and complexity of hydraulic fractures during the fracturing treatment, from only the primary lateral wellbore or by bi-directional fracturing treatments, in contrast to prior fracturing treatments where the fracture pressure and rock stresses have been retained. The diagnostic method may be used to steer the fracturing treatment away from a neighboring interval that might have retained fracture pressure.

One simple technique to evaluate stress shadowing is as follows: a) with two isolated frac intervals, perform a frac treatment on one and retain the treatment pressure; follow then by fracturing the adjacent (e.g. the left side) interval and image the fracture propagation and complexity; b) do the same as at a) above, but follow the first frac treatment with a frac treatment to the other side (e.g. the right side), and image the fracture propagation and complexity. Compare the a) and b) fracture geometry to see if the stress shadow causes fracture propagation to curve or deviate away. Other, more complex techniques can be performed including, but not necessarily limited to, pressurizing a diagnostic lateral wellbore in the frac interval parallel to the primary lateral wellbore to determine how front-placement stress shadow influences fracture growth, direction and complexity.

In another non-limiting embodiment, at least one diagnostic lateral wellbore in close proximity to hydraulic fractures or extending from at least one primary lateral wellbore along the fracture plane can help determine idea locations for high resolution use of several imaging devices and techniques including LFHI, acoustic imaging, electrolocation imaging and noisy particle imaging techniques and materials which can be used to determine placement of proppants in complex fracture networks during and after a fracture treatment, such as during closure on glass beads, sand, or other proppants, as one non-limiting example. The ability to image proppant distribution will allow evaluation of the importance of proppant size for placement within narrow fractures and complex fracture network regions in the treated intervals. With the use of diagnostic lateral wellbores improved fracture imaging technology can evaluate conventional and new proppant suspension agents. Suspension agents are used to help prevent proppant settling and settling prior to fracture closure. In a non-limiting example, one or more diagnostic lateral wellbore may be used to acquire an image of a particular fracture network at initial distribution and then during and/or after settling of the proppant. Structural, compositional, and/or concentration changes can then be made to the anti-settling agent, density of the proppant, and the like, and continued evaluation of product performance may be made using information generated by the proppant imaging capability. Indeed, many types of conventional and future technologies may be evaluated under field conditions by operators using at least one diagnostic lateral wellbore adjacent to at least one primary lateral wellbore and/or another diagnostic lateral wellbore. That is, there have been major limitations in the ability to accurately, comprehensively and geometrically evaluate the performance of new technology. The ability to differentiate the effectiveness of one technology from another is of significant economic importance for developing and advancing technology for shale completions in the future.

For example, in a four interval series of hydraulic frac treatments where electrolocation devices are placed perpendicularly to the diagnostic lateral wellbore and in the middle of each fracture interval, by using the same frac treatment design and only varying the size and amount of conductive-material coated proppant used in each interval, such as 2 ppa of 30/70 mesh (595/210 microns) in the first interval, 2 ppa of 150 mesh (112 microns) in the second interval, 4 ppa of 200 mesh (74 microns) in the third interval, and 4 ppa of 1.1 specific gravity 200 mesh proppant material in the fourth interval, measurement of electrolocation signals from each of the zones during and after the frac treatments can be performed to see how proppant size-fracture width influence proppant distribution. The proppant distribution tests will also provide criteria about proppant setting within various fracture widths. Additional evaluation tests could be performed with and without proppant “anti-settling agents” for more accurate determination of performance of these agents. The abbreviation “ppa” refers to pounds of proppant added to one gallon of fluid volume.

In another non-limiting embodiment, a diagnostic lateral wellbore may be at various distances from a primary lateral wellbore, for instance at an angle, or in a step-wise configuration with relatively short portions of the diagnostic lateral wellbore substantially parallel to the primary lateral wellbore. In a non-limiting example a single diagnostic lateral wellbore has three distances from a primary lateral wellbore; with the diagnostic lateral wellbore having a substantially parallel section at distance of 50 feet (15.2 m), a substantially parallel section at distance of 100 feet (30.5 m), and a substantially parallel section at distance of 150 feet (45.7 m). There may be further imagined two frac intervals for each substantially parallel lateral wellbore section, for a total of six frac intervals. Diagnostic injection tests are performed at each of the six frac interval for learning at least one or more parameters about hydraulic fracture treatment interaction with geo-specific shale reservoir, including but not limited to, fracture hit time tests for determining the fracture complexity storage modulus. The fracture hit time is the pump time and treatment fluid volume pumped from injection points or sliding sleeves (or the like) to pressure sensors, for the time and volume required when pressure is first indicated. The fracture complexity storage modulus is the total treatment volume ratio to the frac model calculated planar fracture volume between the primary lateral wellbore and diagnostic lateral wellbore (parallel wellbore sections). The diagnostic injection test for each frac interval can consist of one or multiple injection tests besides fracture hit time tests, that is, injection tests with different treatment fluids, with and without a chemical diverter, at different injection rates, at different treatment and/or stage volumes, with different sizes and densities of proppant, with or without tracer materials, and the like, as non-limiting examples. Diagnostic tests performed at different lateral distances (i.e. 50 feet, 100 feet and the like) will help generate data specific for amount of fracture complexity near wellbore (such as 0 feet to about 50 feet (15.2 m) as a non-limiting example), for mid-field fracture complexity (such as 50 feet (15.2 m) to about 100 feet (30.5 m) as a non-limiting example), and for far-field fracture complexity generation capability (such as greater than 100 feet (30.5 m) as a non-limiting example). As another non-limiting example, a near wellbore fracture complex is from 0 feet to about 40 feet (12.2 m), a mid-field fracture complexity is from about 40 feet (12.2 m) to 80 feet (24.4 m), and a far-field complex fractures are approximately greater than 80 feet (24.4 m) from the injection lateral. That is, the fracture complexity volume generated in the section having the first 50 feet (15.2 m) distance frac intervals, would be for determining the near-wellbore fracture complexity for the geo-specific shale evaluated, the fracture complexity volume generated in the section at the 100 feet (30.5 m) length fracture intervals, would be for determining the approximate mid-field fracture complexity produced, and the fracture complexity volume generated in the section at the 150 feet (45.7 m) length fracture intervals, would be for determining the approximate far-field fracture complexity produced. When the resultant difference in hit time and treatment volumes between tests performed on the various parallel lateral wellbore sections are calculated, the results would allow an understanding of how difficult far-field complex fractures (i.e. hydraulic fracture/natural fracture interaction and dilations, etc.) are to obtain, and if the amount of far-field fracture complexity can be determined to increase through changes to the set of diagnostic treatment criteria during comparative diagnostic treatments, including injection rate, fluid viscosity, the type and amount and particle size distribution and/or method of using chemical diverters, and the like, as non-limiting examples for performing diagnostic injection tests between lateral wellbores.

An angled diagnostic lateral wellbore (or wellbore functioning as a diagnostic wellbore) may be at an angle to the primary lateral wellbore with which it is associated (defined as having at least one signal emitted from and/or detected by one to another during an diagnostic injection method described herein) ranging from about 2° independently to about 70°; alternatively from about 5° independently to about 40°.

As mentioned, in one non-limiting embodiment, tracers may be injected through the fracture interval lateral wellbores, such as 62 of FIGS. 1 and 2, and 358 of FIG. 3, where the tracer is unique to each fracture interval. In the FIG. 1 embodiment, the analysis of the produced-from primary lateral wellbores 34 and 44, which are unique to each frac interval, 21-25, may indicate conditions within the frac intervals including, but not necessarily limited to, conductivity, flow rates, flow pressures, fracture network complexity, higher hydrocarbon producing fracture intervals along primary lateral wellbores 34 and 44, diagnostic information of fracture intervals 21-25, production when fractures are treated differently (i.e. treatment pump rate, number of perforation clusters per fracture interval, width of fracture interval, volume of pad and proppant slurry stages), types and/or combination of treatment fluids (i.e. slickwater, VES, linear polymer, crosslinked polymer, foamed fluid, and the like), total proppant placed in the intervals, comparison of long term scale prevention additive effects (e.g. one or two intervals utilizing a slow release inhibitor agent like ScaleSORB™ available from Baker Hughes Incorporated and other zones completed without inhibitor), type of cleanup fluid formulation, type of cleanup process from assisting lateral wellbore 54, comparison of intervals that were quickly forced to fracture closure contrasted with intervals allowed to fracture close naturally over days, production information for use in refrac candidate selection), and the like. Conventionally tracers come from the primary wellbores 34 and 44 (or 344 and 348 in the FIG. 3 embodiment). Introduction of tracers may be done at any time in the methods described herein that include at least one assisting lateral wellbore. In another non-limiting embodiment, various diagnostic processes and/or treatments may be performed on the multiple fracture intervals where other diagnostic techniques can be used with or without tracers for gaining diagnostic knowledge about how treatments and processes perform to optimize completing and producing the geo-specific shale reservoir.

Suitable tracers include, but are not necessary limited to known organic and/or inorganic tracers used in oilfield reservoir diagnostics. The suitable amounts of tracers in the fluids into which they are introduced may range from about 0.001 independently to about 50,000 ppm, alternatively from about 0.01 independently to about 20,000 ppm, and in another non-restrictive version from about 0.1 independently to about 1000 ppm.

Referring back to FIGS. 1 and 2, fracture growth can be on each side of primary lateral wellbores 34 and 44 (i.e. common bi-wing geometry). More specifically, in interval 22, complex fracture networks 60 and 70 extend on either side of primary lateral wellbore 34 and complex fracture networks 100 and 110 extend on either side of primary lateral wellbore 44. The complex fracture networks 50, 70, 90 and 110 generated towards diagnostic lateral wellbore 54 should be, in most cases, perpendicular to primary laterals 34 and 44 and at a given time and injection volume should intersect with diagnostic lateral 54, and thereby increase the pressure of at least one of a plurality pressure sensors (not shown) in an array on diagnostic lateral wellbore 54. At the point of intersection with diagnostic lateral wellbore 54 the hydraulic fracture pressure will be picked up (sensor measured) by one or more pressure sensors in the array, and this can be called a fracture hit time during the diagnostic injection test on the interval. The volume amount of treatment fluid in excess to what has been calculated through a frac model for a planar fracture in the interval that is in between injection location to pressure detection location, will be the inferred volume of complex fracture generated by the HF/NF (hydraulic fracture/natural fracture) interactions (fractures that are crossed, sequestered, branched, dilated, extended, sheared, developed, and the like) during the data-frac test, and in the case of an interval that has 50 feet (15.2 m) distance between the primary lateral 34 or 44 and diagnostic lateral 54, will be related to the volume amount of the near-wellbore fracture complexity. (Note: The bi-wing planar fracture and related dual-side complex fractures generated from primary lateral wellbore 34 or 44 and diagnostic lateral wellbore 54 can be estimated; and more accuracy can be determined by a different data-frac configuration.) As a continuing non-limiting example of acquiring empirical data of HF/NF interactions, dilations, branching, growth extension, and the like, a treatment fluid injection test can be performed on a frac interval to acquire fracture hit time data on a parallel diagnostic section, and optionally a third treatment fluid injection test can be performed at an injection point (sliding sleeve for example) and reservoir injection location of a different frac interval to acquire the treatment fluid volume and time required for obtaining a pressure hit time at a different location on parallel diagnostic section. Results from fracture hit time and/or pressure hit times produced for one frac interval, along with a fracture hit time for a different interval, in combination and independently can be subtracted from each other and as a net subtracted from the treatment fluid volume for pressure hit time to derive in approximation of the relative near-wellbore fracture complexity, mid-field area fracture complexity, along with determining the relative amount of far-field fracture complexity generated for the given diagnostic treatment inject tests conditions. Other data-frac tests in a near-wellbore section, a mid-field section, and a far-field wellbore sections can be performed in respective intervals to further determine the volumetric amounts of HF/NF interactions and resultant distribution of fracture complexity when using different treatment parameters as a method to empirically determine the parameters that influence and/or control the most near-wellbore, mid-field, and far-field generation of fracture complexity for the geo-specific shale reservoir.

The sequence of additional fracture hit times, rate of pressure increase in isolated pressure sub-sections, and the like can be inferred to the fracture network growth, relative location and size of complex fractures, and the like. Injection of additional fluids and materials and the like through a primary lateral wellbore can provide further information, such as influence of type and amount of chemical diverter, viscosity of fluid, rate of fluid injection, transport of wide-size distribution range proppant, ultra-lightweight proppant, and/or tracer tagged proppant to observe type and amount of proppant retained in reservoir versus produced in diagnostic lateral wellbore, the effect of proppant on fracture network closure parameters, including closure time, the duration and volume of treatment fluid produced during forced closure compared to different size, density, concentration, sequence of types, and/or the total amount of proppant placed in fracture network, and the like. In one non-limiting example, the data-frac tests can allow an operator to be aware that the geo-specific shale reservoir has an anisotropic stress differential combined with very small amount of HF/NF interaction, dilation, and resultant fracture network complexity, by showing very little change in fracture hit time compared to planar calculations, with a single pressure hit point along isolated pressure section, and possibly further understood when combined with no other pressure hits in sub-sections of the diagnostic lateral wellbore when changing the injection rate, fluid viscosity, type, amount and/or size of diverter, and the like. In another non-limiting example, fracture complexity may be generated dominantly in the near-wellbore section with very little mid-field and even less far-field fracture complexity generated unless fluid injection rate combined with diverter is used, which change in pressure hit time and pressure hit distribution may change dramatically for far-field interval data-fracs, thereby a method for determining the best parameters for generating both near-wellbore and far-field fracture complexity for the geo-specific shale can be evaluated. It may be understood that by performing diagnostic injection tests with methods and configurations presented herein that a much quicker and more accurate learning of how to stimulate a geo-specific reservoir is now achievable. Valuable information can thus be generated prior to a lateral field being drilled and/or stimulated. Further, trial and error stimulation design learning can be dramatically reduced in time, effort, and cost for shale plays.

It is known in the art that when performing a fracture treatment in conventional land reservoirs and typical offshore frac-pack treatments that the execution of a “data-frac” treatment process is performed before the primary frac treatment to induce, generate, and measure treatment and reservoir parameters for fine-tuning the final fracturing treatment design, that is, to understand the proper injection rate, pad volume, number of proppant stages, the concentration of proppant for the proppant stages, and the like from information generated through an injection step-rate test, fracture breakdown pressure, fracture propagation pressure, reservoir closure time after data-frac injection stops, and for fluid efficiency (fluid spurt and Cw leak-off parameters), and the like. Unfortunately, like other conventional fracturing technology, the data-frac criteria to measure and calculate for customizing the frac treatment design has not been transferable, that is, “data-frac treatments” are not typically performed before shale frac treatments because of shale reservoirs' nano-darcy permeability and thus the inability to know fracture network closure time; number, size, spacing and the like parameters of complex fractures versus planar fracture growth, (i.e. HF/NF interactions); and the like. Data-frac treatments specific for shale reservoirs to gain and/or measure and calculate information of high importance for the determination of specific stimulation treatment parameters for the specific geographic shale, include but are not necessarily limited to: the type of treatment fluids, amount of treatment fluid, fluid injection rate, the size, loading, and total amount of proppant, the effectiveness of chemical diverters, and foremost information on the ability to influence and/or control hydraulic fracture crossing versus dilation interactions with natural fractures and/or weak rock-planes during the fracturing operation. One non-limiting example of executing a shale data-frac is to determine “frac hit times” by injection from the a specific frac interval location in the primary lateral wellbore and observing pressure increase at and along the data collection and/or diagnostic lateral wellbore configured with isolated pressure sections with pressure sensors. In theory, after determining through known or anticipated reservoir parameters, select frac treatment and/or injection test fluid, pump rate, and the like parameters, with use of known frac models a bi-wing planar fracture treatment fluid volume and anticipated time for the planar fracture may be determined to reach the closest point of the diagnostic lateral wellbore, such as 50 feet (15.2 m) away. For terminology reasons the parameter “reservoir complexity storage modulus” is given as the ratio of fluid volume, where the numerator is the total volume of injection and/or frac fluid pumped and the denominator is the frac model calculated volume of fluid for the planar fracture only to reach the diagnostic lateral wellbore. The greater amount of time required, and thereby the greater volume of fluid injected, the bigger the reservoir complexity storage modulus will be. This modulus is in theory the volume of “fracture complexity generated” during the diagnostic data-frac test. Further indirect, inferred and calculated information can be generated, such as number of potential hydraulically induced fractures and/or the average potential width of the non-planar fractures through observation of pressure hits, the relative width or lateral geometry of the potential complex fracture network may be inferred, and the like. Additionally, further injection in the same interval or for the next interval can include tracers of select size particulates, as one non-limiting example, or a chemical diverter as another non-limiting example, and then injected and observed for arrival and/or pressure hits, along the diagnostic lateral wellbore, as well as for fracture hit time changes, and for wider pressure hit distribution along the diagnostic lateral wellbore indicating the diverter improved the hydraulic fracture-natural fracture (and/or weak plane) interaction and complex fracture generation, and the like.

Another non-limiting embodiment is to perform data-frac tests within existing lateral fields, including lateral fields that are near and/or at the end of their economic hydrocarbon production capacity. Since the laterals are already drilled, having vertical wellbores completed, use of at least one existing horizontal lateral wellbore with at least one additional drilling of a diagnostic lateral wellbore may be a more economical means to acquire fracture complexity storage modulus for several economic reasons. Placement of the diagnostic lateral wellbore can be in a non-fraced locale of the field or within areas already fraced, for generation and collection of a range of information. Additionally, for new and older lateral fields, sections of primary and diagnostic laterals can be partially treated, such as eight of sixteen data frac intervals, in one non-limiting example, for determining initial lateral field stimulation treatment design criteria and then for a fracture hit time test at a later time, such as for understanding possible stress changes to the reservoir during a production period, such as for determining engineering and treatment criteria for refrac treatment designs, and the like. That is, the data fracs can be performed at any stage of the well history, and can be staged over a time period for understanding how the reservoirs react initially to stimulation treatment criteria and then also after one or more time periods of reservoir hydrocarbon production. This practice could show limited fracturing initially for some geo-specific shales because later stimulation of sections yet to be fractured may generate, in those sections yet fraced, that more fracture complexity and resultant hydrocarbon production occurs, compared to stimulation of the lateral sections initially and all at once. Much is to still be learned in how to complete and make more economically valuable shale unconventional reservoirs. Later re-injections into prior data-frac treated intervals may also show how over time the hydraulic fracture-natural fracture interactions may change where more fractures are generated, that is, a greater amount of new fractures. It could also be determined if the pressure hits on re-data-fracs give a wider distance of pressure hits along the diagnostic lateral and where the re-data-frac fracture complexity storage modulus showed a substantial increase compared to the initial or first time period data-frac service. Use of data-frac tests may lead to practices such as planning to refrac the same intervals after a time period for generating improved interval fracture geometric complexity and as a method to increase overall production, for instance, injecting from one lateral wellbore to an adjacent diagnostic lateral of relatively close proximity can provide new methods in how to complete and produce lateral fields more economically.

Improvements that may be obtained using the diagnostic lateral wellbores include, but are not necessarily limited to, improving the resolution of images of subsurface volumes and features near wellbores particularly micro-images, acquiring and improving information about the stimulation, cleanup, production and refracturing of shale intervals, the character and complexity of hydraulic fracture networks, improving the ability to control fracture closure, improving treatments and processes for fracture treatment fluids, improving fracture network cleanup, and improving production optimization treatments. Techniques of fracturing adjacent wellbores using information obtained from the one or more diagnostic lateral wellbores will help in the distribution of rock stress, treatment pressure, treatment fluids, diversion fluids or agents, clean-up agents, placement of treatment improvement additives, improving far-field propped fracture conductivity, and/or connection of propped primary wellbore fracture extension to far-field fracture networks. The information obtained by the methods and configurations described herein will be important to specify changes in fracture network generation procedures and parameters based on how a specific shale formation behaves and fractures under certain conditions. This will result in increased treatment efficiency to produce greater fracture complexity and fracture conductivity to maximize hydrocarbon production and total hydrocarbon recovery. The methods and configurations described herein will significantly improve the speed and accuracy of using wildcat wells to locate shale sweet-spots in new geologic or geologic or geo-specific shale plays. Useful imaging diagnostic imaging techniques include, but are not necessarily limited to electrolocation, electromagnetic methods, noisy particles, and the like. Combination with known diagnostic tools and measurement devices, such as DTS, DAS, microseismic, wellbore logging, and the like can improve the amount and accuracy of knowledge gained during practice of the disclosed methods and configurations.

In the foregoing specification, the invention has been described with reference to specific embodiments thereof, and has been demonstrated as effective in providing configurations, methods, and compositions for improving the information about, data about, and parameters of subterranean formations that have been and/or will be hydraulically fractured. However, it will be evident that various modifications and changes can be made thereto without departing from the broader scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, the number and kind of primary and/or diagnostic lateral wellbores, configurations of these wellbores, diagnostic devices, imaging tools, fracturing, cleanup and treatment procedures, treatment fluids, tracers, refracturing methods, specific fracturing fluids, cleanup fluids and gases, treatment fluids, fluid compositions, viscosifying agents, proppants, proppant suspending agents, sequence of method steps, and other components and processes falling within the claimed parameters, but not specifically identified or tried in a particular composition or method, are expected to be within the scope of this invention. Further, it is expected that the primary and lateral assisting wellbores and procedures for fracturing, treating and cleaning up fracture networks may change somewhat from one application to another and still accomplish the stated purposes and goals of the methods described herein. For example, the methods may use different wellbore configurations, components, fluids, wellbores, component combinations, diagnostic devices, different fluid and component proportions, data-frac parameters used, data-frac variables investigated, empirical data generated specific for fracturing software development, and additional or different steps or sequences than those described and exemplified herein.

The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. For instance, there may be provided a method of acquiring data for improving a flow of a hydrocarbon from at least one primary lateral wellbore in a subsurface shale volume having at least one assisting lateral wellbore substantially adjacent to the primary lateral wellbore, where the method consists essentially of or consists of (A) hydraulically fracturing at least one first shale interval in the subsurface shale volume from the at least one primary lateral wellbore in the direction of the at least one assisting lateral wellbore to create at least a first fracture network, where the first fracture network is in fluid communication with the at least one assisting lateral wellbore and/or (B) the primary lateral wellbore has been previously stimulated and there is at least one primary lateral wellbore along the lateral length thereof; a sub-method selected from the group consisting of: (1) ultra-high resolution imaging utilizing moderately-close to ultra-close proximity imaging instruments and processes for determining reservoir production flow within the fractured network to the primary lateral wellbore (2) introducing at least one diagnostic agent into the at least one lateral wellbore through the fracture network and the at least one assisting lateral wellbore, or (3) introducing at least one treatment fluid into the at least one lateral wellbore and the fracture network for treating the at least one lateral wellbore and/or the fracture network with the treatment fluid, (4) imaging flow and changes of flow within the fracture network and (5) combinations thereof.

As used herein, the terms “comprising,” “including,” “containing,” “characterized by,” and grammatical equivalents thereof are inclusive or open-ended terms that do not exclude additional, unrecited elements or method acts, but also include the more restrictive terms “consisting of” and “consisting essentially of” and grammatical equivalents thereof. As used herein, the term “may” with respect to a material, structure, feature or method act indicates that such is contemplated for use in implementation of an embodiment of the disclosure and such term is used in preference to the more restrictive term “is” so as to avoid any implication that other, compatible materials, structures, features and methods usable in combination therewith should or must be, excluded.

As used herein, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.

As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.

As used herein, relational terms, such as “first,” “second,” “top,” “bottom,” “upper,” “lower,” “over,” “under,” etc., are used for clarity and convenience in understanding the disclosure and accompanying drawings and do not connote or depend on any specific preference, orientation, or order, except where the context clearly indicates otherwise.

As used herein, the term “substantially” in reference to a given parameter, property, or condition means and includes to a degree that one of ordinary skill in the art would understand that the given parameter, property, or condition is met with a degree of variance, such as within acceptable manufacturing tolerances. By way of example, depending on the particular parameter, property, or condition that is substantially met, the parameter, property, or condition may be at least 90.0% met, at least 95.0% met, at least 99.0% met, or even at least 99.9% met.

As used herein, the term “about” in reference to a given parameter is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the given parameter). 

1. A method of acquiring data for improving a flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume characterized by having at least one assisting lateral wellbore substantially adjacent to the primary lateral wellbore that has been previously stimulated and where the at least one primary lateral wellbore has a lateral length and comprises at least one fracture network along the lateral length, where the method comprises: a sub-method selected from the group consisting of: (1) ultra-high resolution imaging utilizing moderately-close to ultra-close proximity imaging instruments and processes for determining reservoir production flow within the fractured network to the primary lateral wellbore; (2) introducing at least one diagnostic agent into the at least one primary lateral wellbore through the fracture network and the at least one assisting lateral wellbore; (3) introducing at least one treatment fluid into the at least one lateral wellbore and the fracture network for treating the at least one lateral wellbore and/or the fracture network with the treatment fluid; (4) imaging flow and changes of flow within the fracture network; and (5) combinations thereof.
 2. The method of claim 1 where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are: within about 50 to about 600 feet (about 15 to about 183 meters) of each other, and within 0° to about 70° of the same angle as each other.
 3. (canceled)
 4. The method of claim 1 where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (1) and in the sub-method (1) the ultra-high resolution imaging comprises the use of an array of acoustic generators positioned in the diagnostic lateral wellbore and an array of acoustic sensors positioned along the primary lateral wellbore, and the method further comprises acquiring seismic signals from the acoustic generators by the acoustic sensors.
 5. The method of claim 1 where there is more than one assisting lateral wellbore, where the assisting lateral wellbores are diagnostic lateral wellbores, the sub-method is sub-method (1) and where the sub-method is (1) ultra-high resolution imaging comprising using an array of acoustic generators positioned in at least one of the diagnostic lateral wellbores, or positioned in the primary lateral wellbore, and the method further comprises acquiring the seismic signals from acoustic sensors positioned along different diagnostic lateral wellbores and/or the primary lateral wellbore.
 6. The method of claim 1 where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (2) and in the sub-method (2) the diagnostic agent comprises at least one tracer selected from the group consisting of organic and inorganic tracers, where the tracer is present in a fluid and where the tracer is present in the fluid in an amount ranging from about 0.001 to about 50,000 ppm. 7-8. (canceled)
 9. The method of claim 1 where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (2) and in the sub-method (2) the diagnostic agent is selected from the group consisting of: inorganic scale removal solvents; paraffin removal solvents; asphaltene removal solvents; polymer residue cleanup solutions; water-block removal solutions; and combinations thereof.
 10. The method of claim 1 where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the sub-method is sub-method (3) and in the sub-method (3) the at least one treatment fluid is selected from the group consisting of: water-block removal solutions; a fluid for fines migration removal and/or fines fixation; scale deposition inhibitors; paraffin deposition inhibitors; fluids to remove residual polymer; fluids to remove inorganic scale; fluids to remove organic deposits; diverter materials; and combinations thereof.
 11. The method of claim 1 further comprising at least one fracture interval injection lateral wellbore extending from the at least one assisting lateral wellbore in the direction of the at least one lateral wellbore, where the at least one fracture interval injection lateral wellbore is in fluid communication with the fracture network.
 12. The method of claim 1 the fracture network is a first fracture network and where: the at least one primary lateral wellbore and the at least one assisting lateral wellbore each have a heel and toe with a lateral wellbore length between the heel and toe; the at least one first shale interval is near the toe of the at least one primary lateral wellbore and the at least one assisting lateral wellbore, the at least one primary lateral wellbore and the at least one assisting lateral wellbore being within the at least one first shale interval; there is present a second shale interval between the first shale interval and the heel of the at least one primary lateral wellbore and the at least one assisting lateral wellbore, the at least one primary lateral wellbore and the at least one assisting lateral wellbore being within the second shale interval; where the method further comprises: temporarily isolating a portion of the at least one primary lateral wellbore within the at least one first shale interval from the second shale interval; temporarily isolating a portion of the at least one assisting lateral wellbore within the at least one first shale interval from the second shale interval; hydraulically fracturing second shale interval from the at least one primary lateral wellbore in the direction of the at least one assisting lateral wellbore to create a second fracture network; a sub-method selected from the group consisting of: (1) ultra-high resolution imaging utilizing moderately-close to ultra-close proximity imaging instruments and processes for determining reservoir production flow within the fractured network to the primary lateral wellbore; (2) introducing at least one diagnostic agent into the at least one primary lateral wellbore through the second fracture network and the at least one assisting lateral wellbore; (3) introducing at least one treatment fluid into the at least one lateral wellbore and the second fracture network for treating the at least one lateral wellbore and/or the first fracture network with the treatment fluid; (4) imaging flow and changes of flow within the fracture network; and (5) combinations thereof.
 13. The method of claim 12 where the hydraulic fracturing comprises a stop/start-low viscosity/high viscosity staged diversion process to create complex fractures.
 14. The method of claim 12 where the method further comprises creating at least one planar fracture extending from the at least one primary lateral wellbore in the direction of the at least one assisting lateral wellbore so that the first fracture network, the second fracture network, and the planar fracture are in fluid communication with each other.
 15. The method of claim 1 where the at least one assisting lateral wellbore is a diagnostic lateral wellbore, and the method further comprises: disposing at least one diagnostic device in the at least one diagnostic lateral wellbore; emitting at least one signal between the subsurface volume and the at least one diagnostic device; detecting at least one received signal associated with the at least one emitted signal; and analyzing the at least one received signal to ascertain at least one parameter of the at least one primary lateral wellbore and/or the subsurface volume. 16-17. (canceled)
 18. The method of claim 1 where the at least one primary lateral wellbore and at least one assisting lateral wellbore are in different planes of the subsurface volume.
 19. The method of claim 1 where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are at an angle to each other ranging from about 2° to about 70°.
 20. The method of claim 15 where the at least one parameter is used to decide to refracture the subsurface shale volume and decide how to refracture the subsurface shale volume using a process selected from the group consisting of generating new fractures, injecting diverting fluids, increasing fracture complexity, improving proppant distribution in existing and new fractures, and combinations thereof.
 21. A method of acquiring data for improving a flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume characterized by having at least one assisting lateral wellbore comprising a diagnostic lateral wellbore substantially adjacent to the primary lateral wellbore that has been previously stimulated and where the at least one primary lateral wellbore has a lateral length and comprises at least one fracture network along the lateral length, where the method comprises: a sub-method consisting of ultra-high resolution imaging comprises using an array of acoustic generators positioned in the diagnostic lateral wellbore and an array of acoustic sensors positioned along the primary lateral wellbore, and the method further comprises acquiring seismic signals from the acoustic generators by the acoustic sensors; where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are: within about 50 to about 600 feet (about 15 to about 183 meters) of each other, and within 0° to about 70° of the same angle as each other.
 22. The method of claim 21 where: the at least one primary lateral wellbore and at least one assisting lateral wellbore are in different planes of the subsurface volume; and the at least one primary lateral wellbore and the at least one assisting lateral wellbore are at an angle to each other ranging from about 2° to about 70°.
 23. A method of acquiring data for improving a flow of hydrocarbons from at least one primary lateral wellbore in a subsurface shale volume characterized by having at least one assisting lateral wellbore comprising a diagnostic lateral wellbore substantially adjacent to the primary lateral wellbore that has been previously stimulated and where the at least one primary lateral wellbore has a lateral length and comprises at least one fracture network along the lateral length, where the method comprises: a sub-method consisting of introducing at least one diagnostic agent comprising a tracer into the at least one primary lateral wellbore through the fracture network and the at least one assisting lateral wellbore, where the tracer is selected from the group consisting of organic and inorganic tracers, where the tracer is present in a fluid and where the tracer is present in the fluid in an amount ranging from about 0.001 to about 50,000 ppm where the method of further comprises at least one fracture interval injection lateral wellbore extending from the at least one assisting lateral wellbore in the direction of the at least one lateral wellbore, where the at least one fracture interval injection lateral wellbore is in fluid communication with the fracture network.
 24. The method of claim 23 where the at least one primary lateral wellbore and the at least one assisting lateral wellbore are: within about 50 to about 600 feet (about 15 to about 183 meters) of each other, and within 0° to about 70° of the same angle as each other. 